FERC clarified Friday that its February order requiring new generators to provide primary frequency response did not imply that existing generators are entitled to compensation for providing the service (RM16-6-001).
Order 842 required transmission providers to amend their pro forma generator interconnection agreements (GIAs) to require generators have governors or other equipment to respond automatically to frequency disturbances. (See FERC Finalizes Frequency Response Requirement.)
PJM requested a clarification on the order, saying some stakeholders have questioned the RTO’s authority to require existing facilities to provide primary frequency response without compensation.
In its order Friday, FERC dismissed the notion that Order 842 created a blanket prohibition on frequency response requirements on existing generating facilities, saying such a conclusion would be “inconsistent with the fundamental purpose” of the order in ensuring adequate frequency response capability.
“In setting forth requirements for primary frequency response capability and operations, the commission did not address and therefore did not nullify existing requirements for the provision of primary frequency response for existing generators,” FERC said. “We find that Order No. 842 does not relieve existing generating facilities from existing requirements for primary frequency response, including requirements set forth in transmission provider tariffs or business practice manuals, including operating requirements for governors or equivalent controls and/or sustained response.”
The commission said the order also does not prevent transmission providers from proposing additional frequency response requirements under Section 205 of the Federal Power Act, “including requirements for existing generating facilities.”
FERC also rejected AES’ request to reconsider its decision not to mandate compensation for providing frequency response. AES said the lack of compensation “is directly preventing the wide-scale deployment of the very technology that could arrest the aggregate decline in systemwide primary frequency response most efficiently — lithium batteries.”
The company said Order 842’s reference to an individual company’s right to seek compensation under Section 205 of the FPA “is of little consolation to companies currently trying to plan investments on a nationwide basis.”
FERC said AES’ rehearing request did not provide any new information the commission had not already considered and that the company did not address the commission’s findings that the costs of installing and operating a governor or equivalent controls are minimal.
The commission also rejected a rehearing request from Arizona Public Service, which suggested that subjecting projects in the later stages of the interconnection queue to the order’s requirements could be unduly burdensome. “APS provides no specific information that would persuade us to modify Order No. 842’s applicability criteria,” the commission said.
MISO will not move forward with an economic project in MISO South this year, based on results from the RTO’s market congestion planning study.
In June, MISO reported that it was focusing on just one area of concern in MISO South in the annual study: the congested 115-kV Natchez area on the southern Mississippi-Louisiana border. However, the RTO said last week that none of the five economic project candidates meant to alleviate the congestion could yield enough benefits to be viable. (See “5 Focus Areas in Market Congestion Planning Study,” MISO Planning Advisory Committee Briefs: June 13, 2018.)
| MISO
“We are not going to be going to the board for any economic projects in the South region,” MISO’s Jordan Cole said during an Aug. 23 MISO South Subregional Planning Meeting.
According to the RTO, a pending reliability project in the 2018 Transmission Expansion Plan will reduce congestion in the Natchez area. Cole said the $22 million, 115-kV line rebuild from Red Gum, La., to Natchez, Miss., will provide enough relief to defer a major project. The project is expected to be in place by early 2021.
“There’s still some residual congestion, but not enough to lead to an … economic project,” Cole said.
Meanwhile, the RTO’s study for MISO Midwest has identified three projects passing the 1.25:1 benefit-cost threshold so far, although the analysis is not complete. MISO in June said it was focusing on four project candidates in four separate locations in MISO Midwest.
Last year’s MISO’s market congestion planning study, which focused exclusively on MISO South, produced the RTO’s second competitively bid project under Order 1000: the 500-kV Hartburg-Sabine junction project. (See “MISO Reviewing Hartburg-Sabine Proposals,” MISO Informational Forum Briefs: July 24, 2018.)
Barring an unexpected heatwave or a sudden loss of generation, the remainder of the ERCOT market’s summer “looks to be a disappointment” for those hoping for high power prices, according to investment research firm Morningstar.
“We saw some short-lived excitement in July with new demand records set, but lower temperatures look to be sticking around for the rest of August,” the Chicago-based firm said in its Aug. 15 report, “ERCOT and the End of Summer.”
Lower temperatures have replaced the extreme highs of July, when a dome of high pressure settled over Texas and sent temperatures to nearly 110 degrees Fahrenheit. ERCOT broke its system demand record 14 times during July 18-23, with the new mark of 73.3 GW on July 19 smashing the 71.1 GW set in 2016. (See Plentiful Generation Helps ERCOT Meet Extreme Demand.)
July 19, 2018 Wind and Load Profile (Houston, Tx temperatures) | ERCOT, NOAA, Morningstar
“The cooler outlook should keep August prices in the same range as June,” Morningstar said, pointing to a North Hub settlement of $36.99/MWh on the Intercontinental Exchange trading platform. July’s peak settlement was $112.15/MWh, but August’s prices fell to below $45/MWh on Aug. 10.
“Unless a major heatwave hits or a drop-off in wind generation occurs during the last week of August, we will probably see prices settle around [the] $40/MWh range,” the report said.
ERCOT load exceeded 70 GW for 11 straight days in July, a string that was broken on July 27. Load hasn’t broken 70 GW since, peaking at 69.8 GW on Aug. 23.
Morningstar said an increase in wind energy since July has helped depress prices. ERCOT said wind generation has accounted for 4-7 GW of energy during the summer, in line with its expectations. Wind averaged an above-average daily output of 6.1 GW in August. Without the low wind during high temperatures, generators’ hopes for high prices failed to materialize.
| ERCOT, Morningstar
“If August wind generation continues at this level, it may buck the trend of being the lowest generation month and keep prices somewhat subdued,” the firm said.
“The market performed as it was designed to perform,” said Public Utility Commission Chair DeAnn Walker in a statement to RTO Insider. “Whether or not the parameters of the market design need to be adjusted will be something the commission and the market discuss this fall” as it reviews ERCOT’s summer performance (Project 48551.)
ERCOT’s Independent Market Monitor declined to comment, saying it is in the midst of analyzing summer outcomes.
August TAC Meeting Canceled
The Technical Advisory Committee’s leadership has canceled its Aug. 30 meeting, citing a “limited number of items to be considered” this month. It is the third TAC meeting to be canceled this year, and the second in three months.
The TAC meets again Sept. 27 before the next Board of Directors meeting on Oct. 9.
The annual TAC/TAC Subcommittee structural and procedure review will be held Sept. 13.
MISO is planning to provide storage with make-whole payments for price volatility, subject storage resources to dispatch and regulation performance rules, and exempt storage from certain uplift charges, officials said last week at a special conference call on compliance with FERC Order 841.
The RTO is proposing to use the same uninstructed deviation threshold it uses for other generators, Market Quality Manager Jason Howard said during the call on Aug. 21. MISO is currently refining a proposal to implement a more performance-based uninstructed deviation threshold. (See “Final Uninstructed Deviation Proposal,” MISO Market Subcommittee Briefs: May 10, 2018.)
Electric storage resources will be eligible for day-ahead margin assistance payments when they are dispatched below their day-ahead megawatt commitment and revenue sufficiency guarantee payments when they are dispatched in real time above their day-ahead commitments. They will also receive RSG payments when committed above their real-time economic minimum limit when committed in real time under a must-run commitment.
Storage could also be manually redispatched by MISO operators to contradict their day-ahead schedule or real-time offers, even to zero output, RTO staff said.
The RTO is also planning to exempt storage from its revenue neutrality uplift charge, its demand response resource uplift charge, and load ratio share adjustments and ancillary distributions. However, MISO said there was a potential for storage resources to be assessed real-time RSG distribution charges.
MISO plans to vet its performance rules with its Independent Market Monitor.
“We’ve just begun our collaboration with the Market Monitor … so that they do have an initial glimpse of our thoughts,” Howard said. He added that MISO will return with any rule changes regarding threshold and performance at the Sept. 13 Market Subcommittee meeting.
Some stakeholders asked for more specifics about MISO’s Order 841 compliance filing. The RTO said in June it would respond to Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.)
The Energy Storage Association’s Rao Konidena, formerly a MISO adviser, said storage owners must be able to switch among multiple market services, for example regulation to spinning and energy to regulation.
The ESA wants MISO to revise its proposal so that the RTO receives telemetered data in real time when an offline storage resource “returns to interacting with the grid” and can update the state-of-charge in offer parameters for the next dispatch interval. Konidena said that MISO has agreed that a resource’s state-of-charge when returning from offline mode may deviate from the resource’s last metered setpoint.
“MISO has recognized that a storage asset may go into offline mode and leave the market but still remain active charging and discharging to and from other sources and sinks,” Konidena said.
He also said MISO and its Monitor must address how such state-of-charge deviations when returning from offline would be handled.
“The concern is we would be penalized for that behavior,” Konidena said.
Responding to a ruling from a federal appeals court, FERC last week instructed Pacific Gas and Electric and the California Public Utilities Commission to brief it on whether California law allows PG&E to quit CAISO.
The question may be academic; there’s no indication PG&E wants to leave CAISO. But FERC’s ruling on the matter could be worth $30 million a year to the company.
The reason: If PG&E can leave CAISO when it wants, the utility is entitled to continue collecting a 50-basis-point return on equity to remain part of the state’s organized electric market. If it can’t quit, then it could lose its yearly incentive adder.
| PG&E
Ruling in response to a challenge by the PUC, a three-judge panel of the 9th U.S. Circuit Court of Appeals directed FERC in January “to inquire into PG&E’s specific circumstances, i.e., whether it could unilaterally leave the Cal-ISO and thus whether an incentive adder could induce it to remain in the Cal-ISO.”
If PG&E legally must remain part of CAISO, then the company is being paid for something it is already required to do, the panel wrote.
In its Jan. 8 ruling, the appeals court found that FERC had “arbitrarily and capriciously” awarded PG&E the incentive adder without determining whether the company was being incentivized to stay in CAISO, as required by the commission’s regulations. The court remanded the case to FERC to make that determination.
In response, FERC on Monday asked PG&E and the CPUC to brief four issues, including whether California law requires PG&E to participate in CAISO and whether FERC must defer to the PUC’s interpretation of state law (ER14-2529-005).
The controversy over whether PG&E is entitled to the incentive payments has been going on for years.
In the Energy Policy Act of 2005, Congress amended the Federal Power Act to require FERC to provide financial incentives to induce utilities to join RTOs.
FERC responded in 2006 with Order 679, which provided adders to the rate of ROE for utilities that participate in transmission organizations. The bonuses were meant to give utilities an extra reason to join or remain members of RTOs, which are generally voluntary.
The PUC, however, argues that membership in CAISO is mandatory for the state’s three big investor-owned utilities, including PG&E.
PG&E contends participation is voluntary. For staying in CAISO, PG&E has requested and received adders under Order 679 since 2007.
The PUC protested in years past and again in November 2017, saying the $30 million adder was an “unjustified windfall” at the expense of California ratepayers. The Sacramento Municipal Utility District joined the protest.
FERC dismissed the objections, but on appeal the 9th Circuit judges ruled FERC commissioners had abused their authority.
The FERC commissioners, the court said, did not reasonably interpret Order 679 as justifying adders for remaining in a transmission organization. Instead, the commission created a generic adder in violation of the order, the judges ruled.
Order 679 says FERC “will approve, when justified, requests for ROE-based incentives for public utilities that join and/or continue to be a member of” RTOs.
“If all utilities that continued to be members of transmission organizations automatically qualified for incentive adders, the ‘when justified’ language would be surplusage,” the appellate panel wrote.
Briefs from PG&E and the PUC must be submitted to FERC by Sept. 19.
The ranking members of the House and Senate energy committees sent FERC Chairman Kevin McIntyre a letter Wednesday demanding answers on what they called “highly partisan political remarks” by FERC Chief of Staff Anthony Pugliese.
Rep. Frank Pallone Jr. (D-N.J.) and Sen. Maria Cantwell (D-Wash.) told McIntyre they were “deeply troubled” by Pugliese’s statement at an industry conference Aug. 7 that FERC is working with the Department of Energy and National Security Council on the Trump administration’s “ill-conceived plan to interfere with the operation of the nation’s wholesale electric markets. We believe this action would violate the requirement that FERC remain a neutral and unbiased decisionmaker.”
Pugliese, a former lobbyist in Pennsylvania’s capital, and an unsuccessful state legislative candidate there, joined FERC in August 2017 after a stint at the U.S. Department of Transportation as a member of President Trump’s so-called “shadow cabinet.”
Pallone and Cantwell expressed concern over Pugliese’s Aug. 7 remarks at a conference of the American Nuclear Society and his interview with the right-wing outlet Breitbart in July, saying they “call into question his impartiality and independence from political pressure. Left unchecked, we believe such statements must ultimately call into question the impartiality and independence of the commission itself.”
During the appearances, Pugliese praised Trump and criticized Democratic governors for blocking pipelines.
“You still have some parts of the country that are controlled by members of the Democratic Party that are determined to make sure that no infrastructure goes through their states,” Pugliese said in his interview on Breitbart.
“The president has done a tremendous job of knocking down barriers to allow the economy to grow and prosper,” Pugliese added.
At the American Nuclear Society conference, Pugliese seemed to identify himself as a member of the Trump administration, ignoring FERC’s traditional independence.
In introducing Pugliese, Donald Hoffman, CEO of Excel Services, described his job as coordinating “all the activities between the five commissioners, the staff and the White House. He is S2 at FERC, which means he is basically like the deputy director, and he’s responsible for coordinating all the activities and ensuring that the policy issues are discussed appropriately.”
FERC chiefs of staff serve at the pleasure of the chairman. But Pugliese joined FERC about the same time as interim Chair Neil Chatterjee, almost four months before McIntyre.
McIntyre seemed to mark his independence in January when he joined in a 5-0 vote rejecting Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to save at-risk coal and nuclear plants and instead opened a docket to consider resilience concerns. In June, however, Trump ordered Perry to save coal and nuclear plants under an obscure Korean War-era law. (See More Questions than Answers for FERC, RTOs on Bailout.)
At the conference, Pugliese said FERC was working to identify and preserve the most critical generating plants on the grid.
“We are currently working with the House and Senate — when I say we, I mean the administration, the White House and FERC — to consider what legislative changes may need to take place to make sure that we have the authority and the ability to do just that,” he said, according to audio of his remarks, which were shared with RTO Insider by Rod Adams of Atomic Insights.
Pugliese described having “the scary job of literally sitting in a SCIF [sensitive compartmented information facility] all day and hearing about what all these … countries and nations and players are trying to do to us. And then, when we have a well populated part of the country having to import LNG from Russia because we can’t get infrastructure to provide American energy, that’s an area of concern.”
Pugliese made clear he supports payments to nuclear plants.
“We are working with DOD and DOE and NSC to identify the plants that we think would be absolutely critical to ensuring that not only our military bases but things like hospitals and other critical infrastructure are able to be maintained, regardless of what natural or man-made disasters might occur,” Pugliese said.
Pallone and Cantwell told McIntyre “you have the responsibility, as chairman, to safeguard the commission’s independence, its neutrality and its impartiality, and to uphold the professional conduct of the commission’s employees, and most especially those on your own personal staff.”
They asked the chairman to answer several questions, including whether Pugliese’s remarks “represent the views of the commission or any of its members” and whether the chairman had authorized Pugliese to “speak publicly about matters pending before the commission on behalf of the commission?”
Through a FERC spokesman, McIntyre and Pugliese declined to answer similar questions from RTO Insider on Aug. 13.
With the departure of Commissioner Rob Powelson — a Republican who had been outspoken in opposition to out-of-market payments to generators — Trump has a chance to appoint a new commissioner who may be more pliant in response to his efforts to support coal and nuclear.
Politico reported earlier this month the president plans to nominate Bernard McNamee, head of DOE’s Office of Policy, who has previously lobbied for coal and nuclear subsidies. Last November, McNamee joined Pugliese at a breakfast meeting of the Consumer Energy Alliance on the sidelines of the National Association of Regulatory Utility Commissioners’ Annual Meeting in Baltimore to make the case for coal and nuclear price supports. (See DOE, Pugliese Press ‘Baseload’ Rescue at NARUC.)
Despite its name, the CEA lists more than 230 corporate and business members, including utilities, chambers of commerce and trade groups. Watchdog group the Energy and Policy Institute has described CEA as “a fossil fuel-funded advocacy group.”
SPP has ensured it will be one of the key players in the Western Interconnection through at least 2020, having agreed to administer a FERC tariff that mitigates congestion on transmission lines through controllable devices.
The RTO announced Tuesday it began administering the Western Interconnection Unscheduled Flow Mitigation Plan (WIUFMP), effective Aug. 20, for six qualified owners and operators (QOO): CAISO, NorthWestern Energy, NV Energy, PacifiCorp, Tri-State Generation and Transmission Association and Western Area Power Administration.
SPP COO Carl Monroe said he is proud the QOOs recognized the RTO’s “experience and expertise” in reliability, grid management and “complex settlements processes.” The mitigation plan “comes at an exciting time as we’re looking for opportunities to bring SPP’s customer-focused business model to the west,” he said.
SPP has been working to add the Mountain West Transmission Group to its membership rolls since early 2017 and is also competing with CAISO to provide reliability coordination in the Western Interconnection. (See WAPA Formally Requests SPP’s RC Services.)
The WIUFMP defines ways to compensate QOOs for using phase-shifting transformers to manage loop flows in the Western Interconnection. The transformers change the effective resistance of an electric circuit or component to alternating current, such that collectively “the path of least resistance” is modified and certain loaded transmission facilities are relieved of real-time congestion.
Under the tariff, device owners are compensated for the availability and use of their equipment in managing grid congestion along qualified paths. As the plan’s administrator, SPP will collect fees from applicable entities — organizations that generate power, serve load and buy, sell or transport energy in the West — and make payments to device owners.
SPP said it anticipates it will distribute $3 million in the first year of its oversight. It will also collect, analyze and publicly report data on device usage and other aspects of the WIUFMP’s execution.
The Western Electricity Coordinating Council (WECC) had previously administered the mitigation plan, which has been under a FERC-approved tariff since March 2016 (ER16-193). WECC announced in late 2016 it would stop administering the WIUFMP, saying the function no longer fit with its responsibilities as a NERC regional entity.
SPP said it has not “specifically functioned” as a plan administrator for congestion mitigation but has previously performed reliability, settlements and other functions on contract for non-members.
“SPP is always interested in pursuing growth,” SPP spokesman Derek Wingfield told RTO Insider. “Everything we’re doing as the WIUFMP administrator leverages tools, staff, processes and expertise we already have in place. We consider there to be value in any opportunity like this one to use existing assets to bring value to new customers. Our hope is that they receive unparalleled service, we gain experience from the opportunity, and everyone benefits.”
Wingfield said SPP will charge an administrative fee “as allowed by the plan” and accrue other benefits as it does with its other contract services.
“Sometimes we benefit through learning, sometimes by opportunities to offset fixed costs, and sometimes we get to forge or strengthen relationships that may lead toward full SPP membership,” he said.
SPP has already formed a Qualified Owners and Operators stakeholder group, chaired by Tri-State Senior Manager of Transmission Systems Operations Keith Carman. CAISO’s Larry Bellnap, manager of balancing authority operations, is the group’s vice chair.
An Unscheduled Flow Committee, which supports the WIUFMP under SPP’s administration, reports to the QOO.
The QOO began meeting in late 2017, following WECC’s decision to end its role. The group selected SPP following a solicitation in November 2017.
SPP’s initial term as WIUFMP administrator will last through Dec. 31, 2020. It will automatically renew in successive one-year terms unless the QOOs choose another administrator.
MISO is planning a study to ensure external resources bordering more than one of its local resource zones participate in only one zone in the RTO’s annual Planning Resource Auction.
The proposed electrical connectivity analysis will be included in MISO’s second attempt to win FERC approval to create external resource zones in its capacity auction. It will study the links maintained by external resources bordering more than one MISO local resource zone, MISO staff said during an Aug. 22 special conference call of the Resource Adequacy Subcommittee.
FERC rejected MISO’s first filing for external zones, taking issue with MISO’s proposal to allow external resources bordering two local resource zones to choose the zone in which they receive auction credits. The commission also rejected MISO’s plan to make holders of evergreen supply contracts eligible for excess auction revenues indefinitely. (See MISO Promises External Capacity Zones After FERC Rejection.)
The electrical connectivity analysis will measure a generator’s impacts on tie lines, transmission facilities in each zone it borders and zonal transmission import and export constraints. After the study, the external resource will be assigned to the local resource zone with which it shares the greatest electrical connection.
MISO Director of Resource Adequacy Coordination Laura Rauch said the analysis will ensure external resources on the borders don’t receive local credit in more than one zone and market participants don’t have the ability to influence capacity prices.
Rauch said the proposed analysis will take into account the flow of capacity on the system.
“We do … agree with FERC that there should be more specificity for accreditation beyond line ratings,” she said.
Because MISO’s proposed analysis involves a unit-specific approach, Rauch said MISO isn’t allowed to publicly post accreditation results.
“The result will be confidential, so we want to make sure the process is as transparent as possible,” she said.
Customized Energy Solutions’ Ted Kuhn asked if MISO could simply “scrub the names” and release results of the analysis. Rauch said stakeholders might still be able to identify the units based on which transmission lines MISO studied, though she said MISO will evaluate what it could release without revealing confidential information.
MISO plans to refile its external zone proposal with FERC by Aug. 31, hoping for approval sometime in October. Rauch said the timing of the filing should give MISO enough time before deadlines start approaching for the 2019/20 planning year capacity auction.
2-Year Cutoff
MISO’s refiling will also seek to prohibit external resources with historic supply contracts containing evergreen extension options from receiving excess auction revenues after the original contract term is up. MISO’s first filing allowed holders of such evergreen contracts to receive hedges for price separation in perpetuity. FERC said such a rule would have allowed some generation owners to avoid locational price signals indefinitely.
Now, instead of continuously renewing their eligibility, evergreen contract holders will be eligible for hedges until the end of the original term of the agreement or for two years, whichever is longer.
Rauch said the edited provision will also apply to evergreen contract holders who already have a contract extension in place.
“The idea is you get two years to be able to adjust and adapt,” Rauch said.
New Mexico’s largest utility has requested state regulators’ permission to join the Western Energy Imbalance Market, officials announced Wednesday.
Public Service Company of New Mexico (PNM) has applied to join the EIM by 2021, Mark Rothleder, the EIM’s vice president of market quality and renewable integration, told the market’s Governing Body during its meeting in Denver.
PNM, which serves about 510,000 electricity customers in the state, still needs approval from the New Mexico Public Regulation Commission, Rothleder said.
The Governing Body greeted the announcement as good news. If PNM’s request to join the EIM is approved, it could give California and other states access to New Mexico’s wind and solar resources, and New Mexico could draw on California’s solar output during peak usage hours.
Wind far in New Mexico | Public Service of New Mexico
Part of the EIM’s mission is to trade renewable energy between states that generate and use it at different times.
California’s solar energy output reaches its peak midday, during a time of low in-state consumption, while solar farms in New Mexico and Arizona come online earlier, some in time to meet California’s high morning demand for electricity. Wind farms in New Mexico and Wyoming ramp up later in the day, when Californians get home and turn on their lights and TVs.
PNM owns or jointly owns 3,200 miles of electric transmission. It owns, leases or has power purchase agreements for about 2,580 MW of generation, dominated by gas (33%), coal (30%) and nuclear (16%). Its wind capacity totals 300 MW (12%) with solar at 117 MW (5%).
“Having cost-effective electricity available to immediately back up [intermittent] renewable energy in real time supports reliability and also ensures our renewables are used to their fullest potential,” Thomas Fallgren, PNM’s vice president of generation, told the Associated Press on Wednesday.
CAISO started the EIM in 2014, and its members have realized more than $400 million in benefits, including more than $71 million during the second quarter of 2018. (See EIM Benefits Surge to $71.2M in Q2.)
PNM would be the first New Mexico utility to join the EIM.
Major utilities in Arizona, California, Nevada, Oregon, Utah, Washington and Wyoming are already members. Idaho Power and Powerex joined this year.
With Gov. Jerry Brown’s support, CAISO also is pushing to become an RTO for the Western states. A bill to advance the change, AB 813, is pending in the legislature, but its fate is uncertain. It must be delivered to Brown before lawmakers end their current session Aug. 31. (See CAISO Regionalization Bill Cast on Uncertain Course.)
SACRAMENTO, Calif. — A measure to replace generating capacity and limit economic disruption caused by the retirement of the state’s last nuclear power plant is headed to the desk of Gov. Jerry Brown.
Pacific Gas and Electric’s Diablo Canyon Power Plant, which sits on a scenic stretch of coastline south of Big Sur, generates nearly a tenth of California’s in-state power and 20% of the utility’s needs.
Diablo Canyon | PGE
Senate Bill 1090, which passed the State Assembly by 67-1 on Aug. 20, would require Diablo Canyon’s output to be replaced with “a portfolio of greenhouse-gas-free resources,” the first measure of its kind in California.
The bill seeks to avoid a spike in emissions, which occurred after the San Onofre Nuclear Generating Station in Southern California closed in 2013 and fossil-fuel burning plants were brought online to compensate.
The measure directs the Public Utilities Commission to approve full funding for measures to lessen the impact on the local economy and to retain skilled workers until the plant is retired in 2025, when its last Nuclear Regulatory Commission operating license expires. The PUC approved PG&E’s application to retire the plant in January but balked at providing $85 million in community-impact funds and millions more for job retention and retraining, asking the legislature for guidance.
The bill, which cleared the State Senate 31-4 in May, was co-authored by Senate Majority Leader Bill Monning, a Democrat, and Assemblyman Jordan Cunningham, a Republican, both of whom represent districts surrounding Diablo Canyon.
“I am hopeful that Gov. Brown will also be supportive of the safe, reliable and carefully planned retirement of the Diablo Canyon Nuclear Power Plant and sign SB 1090,” Monning said in a statement. “The bill is imperative to the local economy, the state’s energy grid and the region.”
An agreement reached in 2016 among PG&E and environmental and labor groups initially laid out plans for the plant’s closure.
The Natural Resources Defense Council, which helped negotiate the agreement, lauded the bill’s passage.
“The package of policies included in SB 1090 offers a model for the phaseout of aging power plants with clean, increasingly less expensive energy while providing a just transition for workers and communities affected by the shutdown,” NRDC’s western energy director, Peter Miller, wrote in blog post Monday.
A spokeswoman for Monning said she had “no idea … one way or another” whether Brown will sign the bill.
Brown, who has until Sept. 30 to sign or veto the measure, declined to comment on his position. “We typically do not weigh in on pending legislation,” Deputy Press Secretary Brian Ferguson told RTO Insider.
